As recently as 2009, the combustion of fossil fuels provided almost 70% of the electric power in the US, among which coal provided almost half of the total power generation. Given the unforeseeable uncertainty and often turbulence in oil-producing geopolitical areas, it is projected that coal, which has abundant reserves in the United States, would continue to be a dominant fuel for use in electricity generation in the US and other coal-rich regions. Unfortunately, most US coal-fired power plants are over 40-50 years old, and are not equipped with modern and advanced emission control technologies such as flue gas desulfurization (FGD) for SOx removal and selective catalytic reduction (SCR) for NOx reduction. As such, the air pollution emissions accompanying the coal combustion such as SOx, NOx, CO2, and particulates are significant, increasingly causing public health and environment concerns. As a result, Federal and state regulations regarding the emission of air pollutants have recently become more stringent. For example, the newly finalized Cross State Air Pollution Rule (CSAPR) requires the reduction of power plant emissions in 28 states and the District of Columbia. This—rule would require significant reductions in sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions. It requires that by 2014, applicable power plants must reduce their SO2 and NOx emissions to the unit specific allocated levels. On average, all affected units will have to reduce an SO2 by 73 percent and NOx emissions by 54 percent of 2005 levels.
As a result of increasingly stringent regulations, it is anticipated that flue gas desulfurization (FGD) and selective catalytic reduction (SCR) technologies, which are considered the most effective technologies for SOx and NOx emission controls, will be installed in the future years. These post-combustion emission control technologies are expected to cost hundreds of millions of dollars to install and multimillions of dollars to operate and service every year. As some power producing utilities, especially those having mid or low capacities (such as <100-200 MW), have already faced significant pressure from low profit margins, it is not unreasonable to assume that these utilities may simply elect to retire or de-rate their units for economical and environmental considerations.
While installation of FGD and SCR can help utilities to meet their obligations for SO2 and NOx emissions, they have to deal with some other unwanted consequences, including increased parasitic power consumptions, water utilization, and waste generation. Moreover, for power plants that use high sulfur coals, these technologies have an unintended side effect, i.e. making SO3 related corrosion and “blue plume” issues more prevalent.
As one of the less-expensive alternatives, cofiring of coal and biomass fuel blends has gained popularity with the electric utilities producers. Recent studies in Europe and the United States (see M. Sami, K, Annamalai and M. Wooldridge, “Cofiring of coal and biomass fuel bleeds,” Process in Energy and Combustion Science, 27, pp. 171-214, 2001, incorporated by reference) have established that burning biomass with fossil fuels has a positive impact both on the environment and the economics of power generation. The emissions of SO2 and NOx were reduced in most cofiring tests (depending upon the biomass fuel used), and the CO2 net production was also inherently lower, because biomass is considered CO2-neutral. The interest for cofiring arose in the 80's in the U.S. and Europe, around specifically to the use of waste solid residues (paper, plastic, solvents, tars, etc.) or biomass in coal power stations that were initially designed for combustion of coal solely, in order to increase benefit margins from those new opportunity fuels such as reductions in greenhouse gas (GHG) emissions.
Traditionally, biomass has been cofired either directly or indirectly, depending on fuel feeding methods used for both biomass and coal. The most straightforward and cost effective direct cofiring approach is supplying the premixed biomass and coal through a common mill, common feed line and burn with a common burner. Alternatively, in another direct cofiring approach, the biomass can be milled and supplied separately but would be mixed before it is delivered to the burner. Both methods are relatively inexpensive due to shared fuel processing, delivery and combustion equipments, but limited by the amount of biomass blend ratio to typically 5% for pulverized coal (PC) boiler and 10-20% for cyclone and fluidized bed boilers. These direct cofiring approaches also have an insignificant effect upon combustion process and therefore the existing burner can be co-used. Direct cofiring can also be achieved by having a separate biomass processing, delivery line and a dedicated burner. This third direct cofiring method has the advantage of better control over the biomass flow rate, and can achieve higher cofiring ratio (10% or higher for PC boilers, and 20% or higher for cyclone and fluidized bed units) than the previous two direct cofiring methods, but requires a separate feed line and separate burners, and thus increases capital and O&M costs. Furthermore, firing low heating value biomass independently of coal often represents a significant challenge in coordinating controls of both biomass and coal combustions, leading to a risk of poor combustion efficiency.
Indirect cofiring refers to processes in which the biomass fuel is supplied to a separately installed combustor, boiler or gasifier. For example, a separate boiler may be installed to generate steam from firing 100% biomass, and mix the boiler-generated steam with steam generated from an existing coal-fired boiler burning 100% coal. Alternatively, a separate combustor may be installed to fire 100% biomass, and the high temperature flue gas is sent to the convection zone for the existing coal-fired boiler. In yet another alternative and more environmental friendly method, a gasifier is used to gasify the biomass in a separate gasifier, which can be downdraft, updraft or fluidized bed, and the produced hydrogen and carbon monoxide rich synthesis gas (syngas) is supplied to and combusted in the existing coal-fired boiler. The advantages of these indirect cofiring technologies are independent control of operation. However, the capital cost is usually high. In addition, firing coal and biomass fuel in two separate units does not help minimizing or solving the issues with respect to their individual applications. For example, when biomass fuel is fired independently, there is increased corrosion due to high chlorine and alkali metals content in the fuel, though sulfur oxides emission may be low. The ash fusion temperature is also significantly low, which not only cause bed slagging, but also fouling on low temperature heat transfer surfaces. Consequently, it is common that biomass fired boiler generally operates at significantly low temperature, generating low temperature and low pressure steam (e.g. 650 psig and 750° F.), which ultimately leads to a lower electrical efficiency. On the other hand, when coal is fired independently, high temperature and longer reaction time is needed to achieve a higher carbon conversion. At high temperatures, not only sulfur and chlorine corrosion becomes increasingly serious, but also requires expensive materials for boiler and heat transfer surface. High temperature of coal fired boiler makes furnace injection of sorbent for emission control difficult, because of high degree of sorbent sintering and short reaction time achievable.